The invention relates to evaluation of rock formations. More specifically, the invention relates to a method for quantifying permeability of a vuggy reservoir.
A reservoir is a rock formation in which hydrocarbons have accumulated. Before producing hydrocarbons from the reservoir, it is usually desirable to quantify the properties of the reservoir. Among the most important properties are the porosity and permeability of the reservoir. The term xe2x80x9cporosityxe2x80x9d refers to the volume of the pore space expressed as a percent of the total volume of the rock mass, or that volume within the rock formation that can contain fluids. The term xe2x80x9cpermeabilityxe2x80x9d refers to a measurement of the rock formation""s ability to transmit fluids. Formations that transmit fluids readily, such as sandstones and carbonates with larger and well-connected pores, are described as permeable. Impermeable rocks, such as shales and siltstones, tend to be finer-grained or of a mixed grain size, with smaller, fewer, or less interconnected pores. The ability to accurately quantify the porosity and permeability of a reservoir volume is essential for production planning and ultimate hydrocarbon recovery, i.e., the percentage of total hydrocarbons producible from the reservoir over its entire lifespan.
Sandstones usually have a relatively homogeneous pore system. Therefore, the way fluids flow in sandstones may be modeled or controlled so that the hydrocarbon recovery is maximized. In contrast, carbonates often have a heterogeneous pore system. Typically, carbonates have two types of porosity systems: a micro (or matrix) porosity system with small grain-size pores mostly in inter-crystal and intra-crystal forms and a macro porosity system created by alteration of rock. In vuggy carbonates, the macro porosity system is dominated by vugs. Vugs are cavities, voids, or large pores in a rock. Vugs are typically caused by dissolution of the rock. Hereafter, a macro porosity system dominated by vugs will be referred to as a vug porosity system. When flow into a well occurs through two porosity systems, such as a matrix porosity system and a vug porosity system, the reservoir is known as a dual-permeability reservoir.
Historically, hydrocarbon recovery from dual-permeability reservoirs has been low because of lack of understanding of their complex nature. In vuggy carbonates, for example, well-connected vugs which result in very high permeability may concentrate in particular zones and areas of the reservoir. During production, it is common to inject water into the reservoir to sweep the hydrocarbons in various zones of the reservoir. The injected water may all flow into the super-permeability zones, also commonly known as xe2x80x9cthiefxe2x80x9d zones. As a result, only the hydrocarbons in these thin super-permeability zones are swept and produced while the majority of hydrocarbons in the lower permeable zone are left un-swept. This is why hydrocarbon recovery from carbonates is generally much lower than from sandstones. Therefore, it is critical to accurately identify where the high-permeability zones and low-permeability zones are located before any production programs.
From the foregoing, there is desired a method of quantifying permeability of a vuggy reservoir.
In one aspect, the invention relates to a method for quantifying permeability of a vuggy reservoir which comprises determining a permeability modeled with matrix porosity (K0) of the reservoir, determining a vug porosity ("PHgr"vug) of the reservoir, and quantifying permeability (K) of the reservoir as follows:
K=aK0xc2x7bc"PHgr"wg,
where a, b, and c are constants.
In another aspect, the invention relates to a method for quantifying permeability of a vuggy reservoir which comprises identifying a plurality of vuggy and non-vuggy zones in the reservoir, obtaining a permeability modeled with matrix porosity for each of the vuggy and non-vuggy zones, determining a vug porosity for each vuggy zone, and, for each vuggy zone, boosting the permeability modeled with matrix porosity by a factor proportional to an exponential of the vug porosity for the vuggy zone.
In one aspect, the invention relates to a method for quantifying permeability of a dual-permeability reservoir which comprises determining a permeability modeled with matrix porosity (K0) of the reservoir, obtaining a log of the reservoir comprising relative changes in resistively around a borehole penetrating the reservoir, transforming the log into a porosity map of the reservoir, estimating a vug porosity ("PHgr"vug) of the reservoir from the porosity map, and quantifying permeability (K) of the reservoir as follows:
K=aK0xc2x7bc"PHgr"wg,
where a, b, and c are constants.
In another aspect, the invention relates to a method for quantifying permeability of a dual-permeability reservoir which comprises determining a permeability modeled with matrix porosity (K0) of the reservoir, obtaining at least one description of a total porosity of the reservoir, estimating a vug porosity ("PHgr"vug) of the reservoir from the description, and quantifying permeability (K) of the reservoir as follows:
K=aK0xc2x7bc"PHgr"wg,
where a, b, and c are constants.
Other features and advantages of the invention will be apparent from the following description and the appended claims.